This invention relates generally to the field of treating subterranean formations to increase the production of oil and/or gas therefrom. More specifically, the invention pertains to a device and method for injecting fluids into an oilfield wellbore.
When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Lateral holes (perforations) are shot through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing is a routine procedure in petroleum industry operations as applied to individual target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone. Methods for improving treatment coverage are commonly known as xe2x80x9cdiversionxe2x80x9d methods in petroleum industry terminology.
New techniques to improve diversion and treatment effectiveness for hydraulic fracturing or acid stimulating are described in U.S. patent application Ser. No. 09/891,673, and U.S. Pat. No. 6,394,184. These techniques require wireline, slickline, coiled tubing or jointed pipe to penetrate the wellhead during treatment operations and thus to intersect the injection path of the stimulation fluid entering the wellhead. Currently, protection devices with short stubs of pipe or blast joints are used to shield the wireline or tubing (coiled tubing or jointed tubing) from direct impingement of the stimulation fluids. Using short stubs of pipe or blast joints does not allow full wellbore diameter access for running tools, mechanical plug setting, or logging with large diameter tools. Also, use of short stubs of pipe results in additional expenses and operational delays in rigging down and rigging up flanged/threaded connections to clear the wellhead path for tool work requiring full-bore access.
When wireline or tubing lubricators, or any other type of equipment, is connected to the top of the wellhead, a stagnant pocket of fluid or air is created above the entry point(s) of the stimulation fluid. Diverting and other materials injected into the wellbore during the stimulation treatment, including, but not limited to buoyant ball sealers, may become trapped in this stagnant pocket, and thus compromise the success of the stimulation treatment.
No commercially-available injection devices protect wireline, slickline, coiled tubing, jointed pipe or other encumbering equipment in the wellhead while also permitting abrasive stimulation fluid, to be pumped into the wellhead and providing full-casing bore access. Nor do these commercially available injection devices ensure positive, down-hole displacement of diverting material.
U.S. Pat. No. 4,169,504 (Scott) describes a wellhead device to protect production tubing during abrasive fluid injection using downward and tangential fluid entry into the annulus formed between the casing and production tubing. This device has multi-port injection capability but was intended to protect production tubing only, and hence did not provide for full-diameter casing bore access for stimulation work such as logging, bailer runs, bridge plugs, etc. since the permanently installed production tubing was designed to remain in the wellbore. Furthermore, Scott provides no apparatus or method to insert and remove equipment in and out of the wellbore during fluid treatment.
U.S. Pat. No. 4,076,079 (Herricks, et al.) describes a method and apparatus for fracture treating while maintaining full-diameter casing bore access for running packers and perforating guns before and after the fracture treatment. However, the device and method do not have wireline, slickline, coiled tubing, jointed tubing, or any other stimulation equipment suspended in the wellbore during a fracture treatment, and thus, provide no means to protect the wireline, slickline, coiled tubing, jointed tubing, or other stimulation equipment from abrasive stimulation fluid.
Accordingly, there is a need for a fluid injection device that provides full bore access to the wellbore while protecting any apparatus suspended in the wellbore during fluid treatment. The fluid injection device should also provide means to ensure positive, down-hole displacement of buoyant material.
This invention provides a fluid injection device for use in introducing fluid into a wellbore. The device comprises a main housing having a main central bore extending longitudinally therethrough and being aligned with the longitudinal axis of the wellbore, the main central bore having a diameter at least equal to the inside diameter of the wellbore, thereby allowing wellbore equipment full access to the wellbore; and at least one side fluid inlet bore extending tangentially into the main central bore at a downwardly inclined angle to the longitudinal axis of the wellbore, whereby treatment fluid injected into the wellbore from the side fluid inlet bore will travel in a downward spiral flow pattern thereby reducing impingement of the treatment fluid upon any wellbore equipment positioned in the wellbore.
This invention further provides a method of injecting fluid into a wellbore. The method comprises (a) providing a fluid injection device with a main housing having a main central bore extending longitudinally therethrough and being aligned with the longitudinal axis of said wellbore, the main central bore having a diameter at least equal to the inside diameter of the wellbore, thereby allowing wellbore equipment full access to said wellbore; (b) providing at least one side fluid inlet bore extending tangentially into the main central bore at a downwardly inclined angle to the longitudinal axis of the wellbore, whereby fluid injected into the wellbore from the side fluid inlet bore will travel in a downward spiral flow pattern; and (c) directing fluid injected from the side fluid inlet to enter the main central bore and travel in a downward spiral flow pattern thereby reducing impingement of the injected fluid upon any device positioned in the wellbore.